Generally, more porous rock has more space for holding oil and gas. However sometimes relatively porous rock has low permeability. Permeability is a measure of the ease with which fluids will flow through rock. Shale is an example of rock with relatively high porosity but very low permeability due to the small grain size, which reduces the paths through which hydrocarbons can flow. Porosity of a rock is a measure of its capacity to contain or store fluids and can be calculated as the pore volume of the rock divided by its bulk volume. Rock's primary porosity is determined at the time of its deposition, but secondary porosity develops after deposition of the rock and includes spaces created by leaching or natural fracturing.
One way to stimulate or improve production from low permeability rock formations containing oil or gas is to create or enlarge fractures within the formations by a process called hydraulic fracturing (“facing”). Fracing involves pumping hydraulic fluid (“frac fluid”) at high pressures and rates into a well bore, and then into the formation through perforations formed in the well casing. Perforating a well casing to create openings through which hydrocarbons can flow into the well may induce some fracturing within in the formation immediately adjacent the perforation. Fracing extends fractures already present in the formation, and causes new fractures, resulting in a network of fractures that substantially increases the permeability of the formation near the well bore.
In a “sand” frac a propping agent mixed with and carried by the frac fluid into fractures created and/or enlarged in the formation by the high pressure frac fluid. The sand fills the fractures and holds the rock formation faces apart after pumping of the frac fluid finishes, thereby propping open the fractures through which oil and gas flow more freely into the well bore. An “acid” frac typically does not require use of a propping agent, as the acid creates the fractures in the formation and etches or dissolves the fracture faces unevenly, thereby forming dissimilar fracture faces that can only partially close leaving fractures through which oil or gas can flow more freely.
Common examples of proppants include silica sand, resin-coated sand, and ceramic beads (and possibly mixtures of them.) Because silica sand is the predominant proppant used for fracing, “sand” has become petroleum industry jargon for any type of proppant or combination of proppants used in fracing. Therefore, the term “sand” in the specification and claims refers to any type of propping agent, or combinations of them, suitable for holding open fractures formed within a formation by a fracing operation unless otherwise plainly stated. The term “frac fluid” will be used to refer to any type of hydraulic fluid used for fracing that may be used to form fractures and/or enlarge natural fractures in the formation. Frac fluids may be water-based, oil-based, acid or acid-based, and or foam fluids. Additives can be used to control desired characteristics, such as viscosity. Furthermore, references to “frac fluid and sand” in the context of fracing are intended to also include frac fluid and acid unless the context states or plainly indicates otherwise.
Because of differences in permeability of the rock at each of the perforations due to different porosities or existing fractures (both naturally occurring and caused by perforating the casing), the rate at which frac fluid flows through perforations distributed a long a well bore may, and almost always does, vary along the length of the well bore. When stimulating vertical wellbores over 60 years ago the petroleum industry frequently used a high number of perforations (up to 4 perforations per foot of casing) throughout most of the oil and gas pay zones of a well bore. Such a large number of perforations resulted in the frac fluid and sand flowing first into more permeable rock. This resulted in fractures in the more permeable rock formations being packed with too much of the sand (or acid), which was intended to be distributed reasonably equal through the perforations. The less permeable formations were, consequently, not being sufficiently fractured. Solid, hard rubber balls, referred to as “ball sealers,” were used to stimulate selectively the formation in vertical wellbores with an excessive number of perforations. After pumping a portion of the frac fluid with sand or acid, multiple ball sealers were pumped into the well and carried by the frac fluid to the perforation being stimulated. The balls temporarily sealed some of the perforations—those adjacent to fractures formed in the more permeable rock—and diverted the frac fluid, with the sand or acid, away from the stimulated perforations to other perforations in the next most permeable zone of rock that had not yet been stimulated. After pumping of frac fluid ceases, the ball sealers, no longer being held against the perforations by the differential pressure between the frac fluid within the well bore and the formation, fall off of the perforations to allow hydrocarbons from the fractured formation to flow into the well. However, the need for the relatively large and heavy ball sealers in vertical wellbores was minimized when industry began to selectively perforate only the better permeable zones (commonly referred to as “limited entry”).
For horizontal or highly deviated directional oil and gas wells, the conventional petroleum industry practice today is to frac lateral well bores in stages. The length of a lateral portion of a well may be 4,000 feet to 7,500 feet, or substantially more, with cement typically sealing the void space between the casing and the hole. As with vertical wells, perforations in the well casing are formed to inject the frac fluid and sand or acid into the formation to cause it to fracture. Often 15 to 30, and sometimes more, stages are employed to frac a lateral well bore extending 4,000 to 7,500 feet or more. Each frac stage may have 4 to 8 clusters of perforations, with each cluster typically having 6 perforations.
The purpose of fracing in multiple stages is to distribute a generally equal amount of frac fluid and sand to all perforations in a manner that achieves optimal stimulation of each perforation along the entire length of the lateral portion of the well bore, thereby creating extensive cracking/fracturing of the rock formation surrounding the casing along its entire length. Each frac stage is isolated from the other stages and perforated and fraced separately. The petroleum industry experience of fracing a huge number of horizontal wells drilled to date appears to indicate that a large number of stages are required to ensure that a reasonably equal and sufficient volume of frac fluid and sand are pumped into each perforation. In the past few years, developments in hydraulic fracture technology indicate that superior stimulation results are achieved by using larger volumes of frac fluid and sand (15 million gallons and 15 million pounds of sand and more) pumped at extremely high rates (80 to 100 barrels per minute) and pressures (8,000-9,000 psi and more). The velocity of the frac fluid through the wellbore may reach or exceed 90 feet per second. Therefore, the industry continues to use the high-cost, multiple frac stages in an effort to distribute generally equal amounts of frac fluid and sand to all perforations in the lateral casing.
The commercial value of drilling horizontal wells with longer laterals and multiple stages fraced with larger volumes of frac fluid and sand pumped at high velocity and pressure has been established by achieving robust wells that have higher oil and gas producing rates and estimated ultimate recoveries of oil and gas. Effective frac stimulation of most or perhaps all of the perforations in a horizontal casing creates an extensive fracture system that opens and connects more reservoir rock to the wellbore. However, such frac jobs with a large number of stages are time consuming and expensive due to the repetitive plug, perforate and frac operation required to isolate and frac each individual stage. Completion costs typically represent about one-half of the total drilling and completion costs of a horizontal well. Although it is tempting to reduce costs by reducing the number of frac stages and increasing the number of perforations to be stimulated per stage, fewer stages with more perforations per stage risks partial or unequal stimulation of the perforations within the stages. Wells with ineffective stimulation have lower initial production rates and lower ultimate recovery of oil and gas.